From the Reservoir Limit to Pipeline Flow: How Hydrocarbon Reserves are Produced. 11/10/

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1 From the Reservoir Limit to Pipeline Flow: How Hydrocarbon Reserves are Produced 11/10/

2 Rock Occurance and Production Although carbonates are a smaller volume of rock present, they dominate oil production totals (Mid East fields). Why? Estimate of Rock Occurance and Hydrocarbon Production Occurance Production /10/2011 shale sandstone carbonates 2

3 What routes are open to flow? Individual formations and flow channels within each formation may vary widely in their ability to allow flow of fluids across the reservoir. Permeability variances between horizontal and vertical are usually very large. 11/10/

4 What is the accuracy of the Information? Where are the fractures and large pores in the rock? 11/10/

5 A cross section of a reservoir This type of illustration helps to understand reservoir complexity, compartments, potential pays and water sources. Permeabilities in these pays are reported at 1 to 9 Darcies. 11/10/ Source Karamat Ali, BP Pakistan

6 Segments Rock properties and reservoir character, quality, Reservoir fluid qualities how they change during movement and over time with depletion. Reservoir flow paths and compartments impact on fluid flow The effects of pressure drop and back pressure on fluid flow in the reservoir Well Placement and Impact of Wellbore-to-Reservoir contact Fluid behavior in approach and entry to the wellbore Lift type and optimization of flow from bottom hole through the tubing Operations effect on the flow rate Choke settings Restrictions Separator operations Pipeline Start-ups, operations, shut-downs, stabilizing actions 11/10/

7 permeability (m Pore Size vs. Permeability SDA-01 Balakhany X (SP2) Hg permeability md SDA-01 Fasila B (SP3) Hg permeability md SDA-02 Balakhany VIIIC Hg permeability md SDA-02 Fasila D (SP4) Hg permeability md K md Power (K md) Large connected pores and natural fractures dominate the permeability of a formation. y = x R 2 = Are the flow channels generally known for a reservoir? 100 How can they be found? mean hydraulic radius (mm) 11/10/

8 Reservoir Fluids What a PE needs to understand. What phases are present? Where are they? Do the fluid compositions or quantities change? How? How do fluids and fluid changes affect permeability? 11/10/

9 PVT Properties (Pressure Volume Temperature) Oil Formation Volume Factor how many reservoir barrels it takes to equal a stock tank barrel after the oil volume shrinks during production due to loss of associated gas. Bubble Point Pressure the pressure at which free gas is seen in a reservoir with no gas cap. GOR gas to oil ratio of produced oil. API Gravity (density): API o = [(141.5/SG)-131.5] Dynamic Viscosity the viscosity at reservoir conditions (temperare and associated gas decrease viscosity making the viscosity in the reservoir lower than the viscosity at surface). 11/10/

10 Oil Viscosity (cp) What happens to the oil viscosity during production? Why? 10 Reservoir Fluid Viscosity as a Function of Pressure at 60F ?? Pressure (psia) 11/10/

11 Oil Types Paraffin Base Straight chain hydrocarbons. Natural gas condensates, waxes, lube oils. Naphthene Base Oils Ring or cyclic structure, but single bonds. Usual API gravities below 25 o API. Dominates the longer chain, heavier weight oils. Olefinic Series double bonds in a straight carbon chain. Aromatic Series double bonds in a ring Saturated Hydrocarbons Unsaturated Hydrocarbons 11/10/

12 Oil Types Paraffin or linear carbon chain Aromatic or cyclic structure carbon chain Asphaltene (Naphthene) normally cyclic groups with Nitrogen and Sulfur components (Heavy) 11/10/

13 Hydrocarbon Liquids Crude Oils Condensates (API 40 and above) NGL natural gas liquids LPG Liquified Petroleum Gas LNG Liquified Natural Gas Range of compositions from C2 to C6+ 11/10/

14 Reservoir Brines A vast array of water based fluids from fresh water with very low resistivity to super saturated salt water. Tracking the composition of waters and the changes with time can be beneficial to determine the source of water production and leaks. Tracking the composition of flow back after a workover or a stimulation that uses an injected brine can signal when the job has cleaned up. 11/10/

15 11/10/ Water Analysis Over Time Deep Water GOM Date NaCl Cl Na Ca Mg ph HCO3 Ba SO4 Fe Sr TDS 12/23/04 112,000 67,961 4, /13/05 104,000 63,107 34,000 3, /11/05 101,000 61,286 32,000 3, /24/05 97,000 58,859 31,000 2, ,000 04/28/05 60,400 31,700 2, ,400 05/19/05 59,320 28,100 2, ,140 07/21/05 68,075 36,210 3, ,700 08/11/05 68,075 32,440 2, ,000 11/10/05 58,065 29,000 2, ,508 11/17/05 58,064 29,000 2, ,574 12/29/05 58,064 29,000 2, ,440 01/05/06 60,066 32,000 2, ,832 01/19/06 61,067 2, ,909

16 Brine Reactivity Factors 1. Ion type (usually cations) in fluids moving through the matrix pores (some impact on fluids in fractures but to a lesser extent) 2. Size of the cations 3. Charge on the cation 4. Effective salt concentration higher salt concentrations are usually more effective in controlling mineral concentrations. Due to cation exchange, salt concentration is lost from the brine with rock contact. 5. ph low ph fluids have generally less effect on clays than high ph fluids. 6. Clay location detridal clays (in the matrix body) are usually less reactive than authogenic (in the pore throat forms). 7. Clay type Smectite typically has a high reactivity while kaolinite and chlorite usually have low reactivities. 8. Clay form some clays like illite may have forms like the hairy or spider web deposits that can be more reactive due to higher surface areas. 9. Coatings on clays such as heavy oil fractions can prevent many reactions unless removed by soaps or solvents. 10. Time in contact. 11/10/

17 11/10/ Reactivity of Clays Mineral Typical Area (M 2 /g) Cation Exchange Capacity Range (Meq/100 g) Sand (up to 60 microns) Kaolinite Chlorite Illite Smectite Size ranges for clays depend on deposit configuration. CEC s affected by coatings and configurations.

18 Load Water Recovery Range 5% to 60%+ : the amount of load fluid recovery depends on the formation properties, the fluids properties, the pressure and the time span between pumping and flow back. Assists some surfactants (not all), alcohol, nitrogen gas. Detriments high vertical permeability, high interfacial & surface tension, long shut-in times, low energy, small pore throats. 11/10/

19 Scale Deposition Causes Change in flow conditions make the scale minerals super-saturated and an upset causes precipitation Temperature change Pressure change Outgassing of CO 2 Change in ph Evaporation of water Mixing incompatible waters Contact with existing scale scale crystal growth from ions in the water. 11/10/

20 Rock Structure Lithology or mineralogy describes the solid or matrix portion of the rock, generally the primary mineralogy, e.g., sandstone, limestone, etc. Mineralogy analysis often describes the chemical composition of the components of the rock: sand (SiO 2 ), limestone (CaCO 3 ), dolomite (CaMgCO 3 ), anhydrite (CaSO 4 ), clays, etc. SEM (Scanning Electron Microscope) analysis shows the shape and form of the minerals. 11/10/

21 Evaluation of Damage and Barriers Production Logs Fluid type and entry or exit at specific intervals, Mechanical condition of parts of the well or equipment, Fluid movement (and holdup) along the wellbore. Production History Rates and types of fluids, decline %, water increase, etc. Sudden changes, flood arrivals, workover tracking. Deliverability Tests Isochronal, flow-after-flow, four point tests describe the flow from the formation. Buildup & Draw-down Tests Pressure Transient Analysis (PTA) Investigates damage extent and depth (?), drainage radius, boundaries, etc. Requires some critical assumptions. 11/10/

22 Complexity in the Reservoir Simple Reservoir? Only in a text book. How can this reservoir be produced? What type of completions and what flexibility are needed to effectively deplete the reserves. 11/10/

23 XX Reservoir sanction case geologic model thin eroded formation sheet sandstones internally homogenous laterally/vertically connected post depo erosion sheet sand Eroded sheet sand sheet sand 11/10/

24 Pay Quality Terrace Ramp The XX is a clean and very fine grain bedded to amalgamated sand. Where present, thin shale occurs as interbeds capping turbidite bed complexes. XX architecture ranges from channelforms and parallel lobes to shingled complexes. Erosion has removed much of the XX on the ramp causing moderate to significant baffling which limits the effectiveness of the waterflood. Attribute Range Average Gross h (TVT feet) Net Pay (TVT feet) Net-to-Gross Porosity Sw /10/

25 Inflow What is the flowpath from near wellbore into the reservoir Convergent Flow less and less pore space as fluids near the wellbore higher friction, higher turbulence. Even with a fracture, flow towards a single point becomes restrictive as the inflow point is neared. 11/10/

26 Permeability Permeability, k, is the ability of the rock to transmit fluids. Permeability is controlled by the size of the connecting passages between the pores. Secondary porosity, particularly natural fractures and solution vugs dominate permeability often are 100x the matrix permeability. Permeability is NOT a constant it changes with stress, fluid saturation, produced fluid deposition, stimulations, damage from fluids, etc. 11/10/

27 Relative Permeability Note that the permeability to the starting fluid decreases with invasion of a second phase, and that permeability to the invading phase gradually increases with saturation of that phase. 11/10/

28 Permeability Measurements Absolute Permeability the ability of a rock to transmit a single fluid when it is saturated with that fluid. Effective Permeability the ability of the rock to transmit one fluid in the presence of another when the two fluids are immiscible. Relative permeability the ratio between effective permeability to a specific fluid at partial saturation and the absolute permeability. 11/10/ Source AAPG Basic Well Log Analysis, Asquith. G., Krygowski, S.

29 What is the pressure drop in the Perforation Tunnel The perforations open a very small area in the casing. If that area is filled with sand, the pressure drop increases significantly. Pressure drop through the perf, psi 11/10/ Flow rate in bbls per perf per day SPE

30 Differential pressure, DP, is actually a pressure balance 100 psi 25 psi 10 psi 15 psi 1000 psi or 68 bar Press. Drop Column Densities: Gas = 1.9 lb/gal = 0.1 psi/ft Dead oil = 7 lb/gal = psi/ft Fresh water = 8.33 lb/gal = psi/ft Salt water = 10 lb/gal = 0.52 psi/ft Gas cut flowing oil = 5 lb/gal = 0.26 psi/ft = 1900 psi in a 10,000 ft well = 3640 psi in a 10,000 ft well = 4330 psi in a 10,000 ft well = 5200 psi in a 10,000 ft well = 2600 psi in a 10,000 ft well Where does the pressure drop or DP come from? 10,000 ft or 3050 m 4600 psi or 313 bar DP = 4600 psi reservoir pressure psi flowing gradient for oil psi press drop psi through the choke - 25 psi through the flow line - 10 psi through the separator - 15 psi through downstream flow line psi sales line entry pressure /10/ psi drawdown pressure

31 Liquid Height Over The Pump Does it matter? More fluid height over the pump? Holds more back pressure. Restricts the inflow? May keep gas collapsed! The ideal fluid height over the pump depends on fluid and wellbore characteristics. Less fluid over the pump? Lower BHFP. At higher gas content, pump may become gas locked. Too little fluid increases the potential for pump-off. 11/10/

32 Completions - Tubing Performance unstable region, well may not flow under these conditions. increasing GOR helps at low rates (like a natural gas lift). Too much gas hinders (friction). increasing water cuts mean more pressure is required to flow at same rate. initial tubing performance curve (0% w/c, initial GOR). increasing hydrostatic pressure increasing friction Liquid Flowrate TUBING PERFORMANCE RELATIONSHIP 11/10/

33 How Wells Produce - Production Rate and Tubing Sizing The pressure drops are plotted against flowrate to give inflow performance relationship or IPR the tubing performance curve or lift curve Tubing Performance Curves: Calculated by computer or taken from tables, to predict the pressure loss up the tubing. Depends upon rate, type of fluid (oil vs gas), gas-oil-ratio, water content etc. for different tubing sizes. Bottom hole flowing pressurr If bottom hole flowing pressure is the same as the reservoir pressure the well will not flow Pr Pw Natural flowrate: in this particular case the well will flow naturally at this rate with this tubing in the hole. drawdown 31/ 2 " 41/ 2 " 51/ 2 " The lift curve = 'required pressure' (For a particular sized tubing) Pump pressure (If a higher rate is required) As the bottom hole pressure is reduced the well begins to flow - pushed by the reservoir pressure. The greater the drawdown the greater the flow. The IPR = 'Available pressure' Barrels of Oil per Day Flowrate Inflow Performance Relationship (IPR) and tubing Performance Curves 11/10/

34 Gas breaks out and expands as it flows up the wellbore Expansion of gas occurs as the gas rises from the bottom of the well. The expanding gas can entrain and carry liquid with it if the flow rate reaches critical velocity (the velocity necessary to lift liquid) ft Remember the volume of the gas bubble (and indirectly the velocity of the upward flowing fluid) is controlled by the pressure around it. This pressure is provided by the formation pore pressure and controlled by the choke and other back pressure resistances. 5,000 ft 1075 psi 2150 psi 11/10/

35 Flow pattern changes with gas expansion. One or more flow patterns may be present in different parts of the well. Flow patterns may explain differences in lift, corrosion and unloading. Mist Flow external phase is gas with a small amount of liquid Channel or annular flow Slug or churn flow Depth and Pressure Piston flow Bubble flow Single phase liquid flow 11/10/

36 Effect of increasing GLR on Flowing Bottom Hole Pressure (FBHP) As gas is added, the FBHP decreases due to gas cut liquid. When too much gas is added, the friction from the flowing volume increases. FBHP decreasing flowing fluid gradient Increasing friction Increasing Gas Injection or GLR 11/10/

37 Chokes Variable Chokes - good for bringing wells on gradually and optimizing natural gas lift flow in some cases. Prone to washouts from high velocity, particles, droplets. Solutions - hardened chokes (carbide components), chokes in series, dual chokes on the well head. 11/10/

38 Size of a Bubble Rising in a Liquid Column 292 cm 3 surface 14.7 psi (1 bar) 2 cm ft 2150 psi (146 bar) (1524m) 1 cm ft 4300 psi (292 bar) (3049m) What will the expansion of the bubbles produce at surface? 11/10/2011 Energy and friction. 38

39 3-Phase Horizontal Separator Gas Impingement Plate Mist Eliminator Inlet Liquid Large interface to promote gas separation Oil Water, to disposal well 11/10/

40 Conclusions The Flow System from reservoir to pipeline Every pressure drop lowers production Pressure drops: Converging flow Damaged permeability or natural fractures Low flow capacity fractures Perforations that are partly plugged Liquid in the wellbore Choke backpressures Friction in tubulars Facility backpressures 11/10/